AU2013293508B2 - Multiphase separation system - Google Patents
Multiphase separation system Download PDFInfo
- Publication number
- AU2013293508B2 AU2013293508B2 AU2013293508A AU2013293508A AU2013293508B2 AU 2013293508 B2 AU2013293508 B2 AU 2013293508B2 AU 2013293508 A AU2013293508 A AU 2013293508A AU 2013293508 A AU2013293508 A AU 2013293508A AU 2013293508 B2 AU2013293508 B2 AU 2013293508B2
- Authority
- AU
- Australia
- Prior art keywords
- separation system
- multiphase
- header
- liquids
- circular
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Active
Links
- 238000000926 separation method Methods 0.000 title claims abstract description 133
- 239000007788 liquid Substances 0.000 claims abstract description 140
- 239000007789 gas Substances 0.000 claims abstract description 132
- 239000012530 fluid Substances 0.000 claims abstract description 88
- 238000009826 distribution Methods 0.000 claims abstract description 70
- 238000000034 method Methods 0.000 claims abstract description 41
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 35
- 238000004519 manufacturing process Methods 0.000 claims description 24
- 238000012545 processing Methods 0.000 claims description 6
- 238000013517 stratification Methods 0.000 claims description 6
- 238000007789 sealing Methods 0.000 claims description 4
- 238000011144 upstream manufacturing Methods 0.000 claims description 3
- 238000007872 degassing Methods 0.000 claims description 2
- 239000007787 solid Substances 0.000 claims description 2
- 241000237858 Gastropoda Species 0.000 description 8
- 239000012071 phase Substances 0.000 description 8
- 238000010586 diagram Methods 0.000 description 6
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 6
- 230000009467 reduction Effects 0.000 description 5
- 230000008030 elimination Effects 0.000 description 3
- 238000003379 elimination reaction Methods 0.000 description 3
- 239000007791 liquid phase Substances 0.000 description 3
- 238000012986 modification Methods 0.000 description 3
- 230000004048 modification Effects 0.000 description 3
- 230000008569 process Effects 0.000 description 3
- 239000004576 sand Substances 0.000 description 3
- 230000008901 benefit Effects 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 230000002706 hydrostatic effect Effects 0.000 description 2
- 239000012535 impurity Substances 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 239000008346 aqueous phase Substances 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 238000004581 coalescence Methods 0.000 description 1
- 239000000356 contaminant Substances 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000013016 damping Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000010438 heat treatment Methods 0.000 description 1
- 150000004677 hydrates Chemical class 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- -1 methane clathrates Chemical class 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 239000003921 oil Substances 0.000 description 1
- 238000005498 polishing Methods 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 239000007790 solid phase Substances 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D45/00—Separating dispersed particles from gases or vapours by gravity, inertia, or centrifugal forces
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D19/00—Degasification of liquids
- B01D19/0042—Degasification of liquids modifying the liquid flow
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D17/00—Separation of liquids, not provided for elsewhere, e.g. by thermal diffusion
- B01D17/02—Separation of non-miscible liquids
- B01D17/0208—Separation of non-miscible liquids by sedimentation
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D19/00—Degasification of liquids
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/36—Underwater separating arrangements
Landscapes
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Thermal Sciences (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
- Separating Particles In Gases By Inertia (AREA)
- Gas Separation By Absorption (AREA)
- Degasification And Air Bubble Elimination (AREA)
Abstract
A system and method for separation of liquids and gases within a multiphase fluid are provided herein. The method includes flowing a multiphase fluid into a circular distribution header of a multiphase separation system and separating the multiphase fluid into gases and liquids within the circular distribution header. The method also includes flowing the gases into a circular gas header that is above a plane of the circular distribution header and flowing the liquids into a circular liquid header that is below the plane of the circular distribution header. The method further includes flowing the gases out of the multiphase separation system via a gas outlet line and flowing the liquids out of the multiphase separation system via a liquid outlet line, wherein entrained liquids within the gas outlet line are flowed to the liquid outlet line via a downcomer.
Description
WO 2014/018148 PCT/US2013/039089 MULTIPHASE SEPARATION SYSTEM CROSS-REFERENCE TO RELATED APPLICATION [00011 This application claims the benefit of U.S. Provisional Patent Application 61/676,753 filed July 27, 2012 entitled MULTIPHASE SEPARATION SYSTEM, the 5 entirety of which is incorporated by reference herein. FIELD OF THE INVENTION [0002] The present techniques provide for the separation of gases and liquids within production fluids. More specifically, the techniques provide for the separation of production fluids into gases and liquids using a subsea multiphase separation system. 10 BACKGROUND [0003] This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section 15 should be read in this light, and not necessarily as admissions of prior art. [0004] Any of a number of subsea separation techniques may be used to enhance the amount of oil and gas recovered from subsea wells. However, subsea separation at water depths greater 1500 meters becomes especially challenging due to the environmental conditions. As water depth increases, the external pressure on a vessel created by the 20 hydrostatic head increases the required wall thickness for vessels used for subsea processing. At water depths greater than 1500 meters, this wall thickness has increased to such an extent that typical gravity separation is not practical. In addition, vessels with such a large wall thickness can be a challenge to fabricate, and the added material and weight can impact project economics, as well as the availability of the vessel for maintenance. As a result, large 25 diameter separators often cannot be used at such depths. SUMMARY [0005] An exemplary embodiment provides a multiphase separation system including an inlet line configured to feed a multiphase fluid into a circular distribution header within the multiphase separation system, wherein the circular distribution header is coupled to a number 30 of upper lines and a number of lower lines. Each upper line is configured to feed gases into a -1- WO 2014/018148 PCT/US2013/039089 circular gas header, wherein the circular gas header is in a second plane that is above a plane of the circular distribution header. Each lower line is configured to feed liquids into a circular liquid header, wherein the circular liquid header is in a third plane that is below the plane of the circular distribution header. The multiphase separation system also includes a 5 gas outlet line that is coupled to the circular gas header and is configured to flow the gases out of the multiphase separation system, and a liquid outlet line that is coupled to the circular liquid header and is configured to flow the liquids out of the multiphase separation system. The gas outlet line and the liquid outlet line are coupled via a downcomer configured to allow entrained liquids to flow from the gas outlet line to the liquid outlet line. 10 [0006] Another exemplary embodiment provides a method for separation of liquids and gases within a multiphase fluid. The method includes flowing a multiphase fluid into a circular distribution header of a multiphase separation system and separating the multiphase fluid into gases and liquids within the circular distribution header. The method also includes flowing the gases into a circular gas header that is above a plane of the circular distribution 15 header and flowing the liquids into a circular liquid header that is below the plane of the circular distribution header. The method further includes flowing the gases out of the multiphase separation system via a gas outlet line and flowing the liquids out of the multiphase separation system via a liquid outlet line, wherein entrained liquids within the gas outlet line are flowed to the liquid outlet line via a downcomer. 20 BRIEF DESCRIPTION OF THE DRAWINGS [0007] The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which: [0008] Fig. 1 is a block diagram showing a system for separating production fluids into a gas stream and a liquid stream using a multiphase separation system; 25 [00091 Fig. 2 is a perspective view of a multiphase separation system; [0010 Fig. 3 is a side view of the multiphase separation system of Fig. 2; [1 Fig. 4 is a process flow diagram showing a method for separating gases and liquids within a multiphase fluid; [00121 Fig. 5 is a perspective view of another multiphase separation system; 30 [0013] Fig. 6 is a side view of the multiphase separation system of Fig. 5; -2- WO 2014/018148 PCT/US2013/039089 [0014] Fig. 7 is a perspective view of another multiphase separation system; and [0015] Fig. 8 is a side view of the multiphase separation system of Fig. 7. DETAILED DESCRIPTION [00161 In the following detailed description section, specific embodiments of the present 5 techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling 10 within the true spirit and scope of the appended claims. [O171 As discussed above, traditional large diameter separators face technical challenges at depths greater than approximately 1500 meters. Thus, embodiments described herein provide an unconventional separation system that is capable of achieving acceptable gas liquid separation and damping potential flow fluctuations, while meeting the size and weight 15 restrictions imposed on deepwater processing units. Further, the separation system can be designed to pipe code instead of vessel code, which may provide cost and weight savings. In many cases, for a given pressure class, the required wall thickness for a pipe is less than the required wall thickness for a corresponding vessel. [00181 According to embodiments described herein, a compact, subsea multiphase 20 separation system is used to enhance subsea well production, especially in deepwater and Arctic environments. In various embodiments, the subsea multiphase separation system is a four phase subsea separator that is configured to separate production fluids into a gas phase, an oil phase, an aqueous phase, and a solid phase. In other words, subsea separation may be used to create single phase streams. This may allow for the usage of single phase pumps, 25 which are more efficient and can achieve larger pressure differentials compared to multiphase pumps. In order to pump a single phase stream, one single phase pump may be sufficient. In contrast, in order to pump a multiphase stream, a series of multiphase pumps may be used to achieve the same pressure differential, especially for high boosting applications. [00191 The separation process described herein may be used to achieve bulk removal of 30 aqueous fluids from production fluids. The removal of aqueous fluids is termed water removal herein, although this may be understood to include water with other contaminants, -3- WO 2014/018148 PCT/US2013/039089 such as salts or other miscible fluids. Such bulk water removal may mitigate flow assurance concerns, by allowing substantially pure oil and/or gas streams to be sent to the surface. These substantially pure streams will form lower amounts of hydrates, such as methane clathrates, thus lowering the risk of plugging or flow restrictions. Further, corrosion concerns 5 can be reduced or eliminated. The sand and water by-product streams can then be disposed topsides to dedicated disposal zones, reservoirs, the seabed, or the like. [0020] Bulk water removal may also result in a decrease in the hydrostatic head acting on the reservoir, thus increasing both the reservoir drive and production. Further, the separation process may be used to reduce flow line infrastructure, reduce the number of topside water 10 treating facilities, reduce power and pumping requirements, and de-bottleneck existing facilities that are challenged with declining production rates due to increased water cuts. [0021] As used herein, the term "slug" refers to a small volume of fluid that is entrained within the production fluids and is often of a higher density than the production fluids, for example, a liquid zone carried along by gas flow in a pipeline. Slugs may affect the flow 15 characteristics of the production fluids. In addition, slugs exiting a pipeline may overload the gas-liquid handling capacity of the subsea, topsides, or onshore processing facility at the pipeline outlet. Thus, according to embodiments described herein, one or more subsea multiphase slug catchers may be used to dampen or remove the slugs from the production fluids before the production fluids enter the export pipelines. 20 [0022] Fig. 1 is a block diagram showing a system 100 for separating production fluids 102 into a gas stream 104 and a liquid stream 106 using a multiphase separation system 108. The production fluids 102 may be hydrocarbon fluids that include a mixture of natural gas, oil, brine, and solid impurities, such as sand. The production fluids 102 may be obtained from a subsea well 110, as indicated by arrow 112. The production fluids 102 may be 25 obtained from the subsea well 110 via any type of subsea production system (not shown) that is configured to produce hydrocarbons from subsea locations. [0023] In an embodiment, the production fluids 102 are flowed into the multiphase separation system 108, as indicated by arrow 114. The multiphase separation system 108 may be any type of vessel that is configured to achieve bulk separation of gas and liquid from 30 the production fluids 102. In addition, the multiphase separation system 108 may remove slugs from the production fluids 102. The multiphase separation system 108 may be implemented within a subsea environment. -4- WO 2014/018148 PCT/US2013/039089 [0024] Within the multiphase separation system 108, the production fluids 108 may be separated into the gas stream 104 and the liquid stream 106, as indicated by arrows 116 and 118, respectively. The gas stream 104 may include natural gas, while the liquid stream 106 may include water, oil, and other residual impurities, such as sand. Designs for the 5 multiphase separation system 108, as well as the mechanisms by which the multiphase separation system 108 may affect the quality of the separated gas stream 104 and the separated liquid stream 106, are described with respect to Figs. 2-8. [0025] In some embodiments, the gas stream 104 is flowed to downstream equipment 120, as indicated by arrow 122. The downstream equipment 120 may include, for example, 10 any type of downstream gas processing equipment, such as a gas compressor, gas treatment facility, gas polishing device, or the like, or a gas pipeline. In addition, the liquid stream 106 may be flowed to downstream equipment 124, as indicated by arrow 126. The downstream equipment 124 may include, for example, oil and water pre-treating or coalescence equipment, such as a heating system, chemical injection system, electrostatic coalescer, or the 15 like, a pipe separator or cyclone for oil-water separation, or a liquid export pipeline. [0026] The block diagram of Fig. 1 is not intended to indicate that the system 100 is to include all of the components shown in Fig. 1. Further, any number of additional components may be included within the system 100, depending on the details of the specific implementation. For example, the multiphase separation system 108 can be designed to 20 achieve liquid/liquid separation, thus delivering two substantially pure oil and water streams to the downstream equipment 124. Further, multiphase and single phase desanders may be placed upstream and/or downstream of the multiphase separation system 108. [0027] Fig. 2 is a perspective view of a multiphase separation system 200. The multiphase separation system 200 may include an inlet line 202 configured to feed the 25 multiphase fluid into a circular distribution header 204. The multiphase fluid may be any type of fluid that includes both liquid and gaseous components. For example, the multiphase fluid may be production fluids from a subsea well. The circular distribution header 204 may be coupled to a number of upper lines 206 and a number of lower lines 208. The upper lines 206 and the lower lines 208 may be perpendicular to the circular distribution header 204. 30 [0028] Each upper line 206 may feed gases within the multiphase fluid into a circular gas header 210. The circular gas header 210 may be in a second plane that is above and substantially parallel to the circular distribution header 204. In addition, each lower line 208 -5- WO 2014/018148 PCT/US2013/039089 may feed liquids within the multiphase fluid into a circular liquid header 212. The circular liquid header 212 may be below and substantially parallel to the circular distribution header 204. [0029] A gas outlet line 214 may be coupled to the circular gas header 210 and may be 5 configured to flow the gases out of the multiphase separation system 200. A liquid outlet line 216 may be coupled to the circular liquid header 212 and may be configured to flow the liquids out of the multiphase separation system 200. The gas outlet line 214 and the liquid outlet line 216 may be coupled via a downcomer 218. The downcomer 218 may be configured at a right angle or an oblique angle. 10 [00301 The downcomer 218 may allow entrained liquids within the gases to flow from the gas outlet line 214 to the liquid outlet line 216. In addition, the downcomer 218 may allow entrained gases within the liquids to flow from the liquid outlet line 216 to the gas outlet line 214. However, in some embodiments, the separation of gases and liquids may be sufficient in the upper lines 206 and the lower lines 208 perpendicular to the circular 15 distribution header 204. In this case, the downcomer 218 may be omitted from the multiphase separation system 200. [00311 The schematic of Fig. 2 is not intended to indicate that the subsea multiphase separation system 200 is to include all of the components shown in Fig. 2. Further, any number of additional components may be included within the subsea multiphase separation 20 system 200, depending on the details of the specific implementation. For example, the liquid outlet line 216 may be extended, with or without an optional sealing downcomer, to increase residence time in the liquid phase and achieve oil/water separation. This may allow for the enhancement or the elimination of downstream oil/water separation steps and equipment. In addition, the liquid outlet line 216 may include separate outlet lines for flowing the oil and 25 water out of the multiphase separation system 200. [0032] Fig. 3 is a side view of the multiphase separation system 200 of Fig. 2. As shown in Fig. 3, the circular distribution header 204 may be in the same plane as the inlet line 202. Thus, the multiphase fluid may flow directly into the circular distribution header 204. Due to the configuration of the circular distribution header 204, the multiphase fluid flow may 30 initially distribute along two flow paths within the circular distribution header 204, resulting in a reduction in velocity of the multiphase fluid as it flows throughout the circular distribution header 204. In some embodiments, such a reduction in velocity of the multiphase -6- WO 2014/018148 PCT/US2013/039089 fluid dissipates any slugs within the multiphase fluid. In addition, the circular distribution header 204 may act as a stratification section that is configured to perform an initial bulk separation of gases and liquids within the multiphase fluid. [0033] The upper lines 206 may be perpendicular to the circular distribution header 204 5 and may couple the circular distribution header 204 to the circular gas header 210. The lower lines 208 may be perpendicular to the circular distribution header 204 and may couple the circular distribution header 204 to the circular liquid header 212. The circular gas header 210 and the circular liquid header 212 may be parallel to the circular distribution header 204. 10034] In some embodiments, the circular gas header 210 acts as a droplet separation 10 section configured to remove entrained liquids from the gases within the circular gas header 210. In addition, in some embodiments, the circular liquid header 212 acts as a liquid degassing section configured to remove entrained gases from the liquids within the circular liquid header 212. [0035] Fig. 4 is a process flow diagram showing a method 400 for separating gases and 15 liquids within a multiphase fluid. In various embodiments, the multiphase separation system 200 discussed above with respect to Figs. 2 and 3 is used to implement the method 400. 10036] The method begins at block 402, at which the multiphase fluid is flowed into a circular distribution header of the multiphase separation system. The multiphase fluid may be flowed into the circular distribution header via an inlet line of the multiphase separation 20 system. 100371 At block 404, the multiphase fluid is separated into gases and liquids within the circular distribution header. The circular distribution header may be a stratification section that allows for an initial bulk separation of the gases and liquids. However, some amount of liquids may be entrained within the gases, and some amount of gases may be entrained within 25 the liquids. In addition, the circular distribution header may dissipate any slugs that are within the multiphase fluid. [0038] At block 406, the gases are flowed into a circular gas header that is above a plane of the circular distribution header. The gases may be flowed into the circular gas header via a number of upper lines that are perpendicular the circular distribution header. In various 30 embodiments, the velocity and pressure of the gases are lowered by splitting the gases among the upper lines. -7- WO 2014/018148 PCT/US2013/039089 [0039] At block 408, the liquids are flowed into a circular liquid header that is below the plane of the circular distribution header. The liquids may be flowed into the circular liquid header via a number of lower lines that are perpendicular to the circular distribution header. In various embodiments, the velocity and pressure of the liquids are lowered by splitting the 5 liquids among the lower lines. [0040] At block 410, the gases are flowed out of the multiphase separation system via a gas outlet line. The gases may be sent to a gas export line or any other type of downstream equipment. At block 412, the liquids are flowed out of the multiphase separation system via a liquid outlet line. The liquids may be sent to a liquid export line or any other type of 10 downstream equipment. [0041]1 As the gases and the liquids are flowing out of the multiphase separation system, entrained liquids within the gas outlet line are flowed to the liquid outlet line via a downcomer. In addition, entrained gases within the liquid outlet line are allowed to rise to the gas outlet line via the downcomer. 15 [0042] The process flow diagram of Fig. 4 is not intended to indicate that the steps of the method 400 are to be executed in any particular order, or that all of the steps of the method 400 are to be included in every cases. Further, any number of additional steps not shown in Fig. 4 may be included within the method 400, depending on the details of the specific implementation. 20 [00431 Fig. 5 is a perspective view of another multiphase separation system 500. The multiphase separation system 500 may include an inlet line 502 that is configured to allow a multiphase fluid to flow into the multiphase separation system 500. The inlet line 502 may include a number of divisions 504 that are configured to lower the velocity of the multiphase fluid and feed the multiphase fluid into a distribution header 506. 25 [00441 The distribution header 506 may be configured to split the multiphase fluid among a number of upper fingers 508 and a number of lower fingers 510. Each upper finger 508 is angled upward to feed into a corresponding upper pipe 512 in a first plane disposed above and substantially parallel to the distribution header 506. Each lower finger 510 is angled downward to feed into a corresponding lower pipe 514 in a second plane disposed below and 30 substantially parallel to the distribution header 506. In addition, each upper pipe 512 may be coupled to a corresponding lower pipe 514 via a downcomer 516. The downcomer 516 may -8- WO 2014/018148 PCT/US2013/039089 be configured perpendicular to the upper pipes 512 and lower pipes 514, or may be at an oblique angle. [0045] Each lower pipe 514 may include an expansion zone 518 that is configured to lower a velocity and a pressure of liquids within the lower pipe 514. This may allow 5 entrained gases within the liquids to rise to the corresponding upper pipe 512 via the downcomer 516. [0046] Each upper pipe 512 may feed into a common gas header 520. The gas header 520 may be configured to lower a velocity of gases within the upper pipe 512 to allow entrained liquids, such as droplets, within the gases to coalesce and drop to the corresponding 10 lower pipe 514 via the downcomer 516. [0047] The multiphase separation system 500 may also include a liquid header 522 for collecting the liquids and flowing the liquids out of the multiphase separation system 500 via liquid outlet lines 524. In addition, the gas header 520 may include gas outlet lines 526 for flowing the gases out of the multiphase separation system 500. 15 [0048] The schematic of Fig. 5 is not intended to indicate that the subsea multiphase separation system 500 is to include all of the components shown in Fig. 5. Further, any number of additional components may be included within the subsea multiphase separation system 500, depending on the details of the specific implementation. For example, the lower pipe 514 may be extended, with or without an optional sealing downcomer, to increase 20 residence time in the liquid phase and achieve oil/water separation. This may allow for the enhancement or the elimination of downstream oil/water separation steps and equipment. Separate oil and water outlets can be included in the liquid header 522 for flowing the oil and water out of the multiphase separation system 500. [0049] Fig. 6 is a side view of the multiphase separation system 500 of Fig. 5. As shown 25 in Fig. 6, the divisions 504 may be in the same plane as the inlet line 502. Thus, the multiphase fluid may be flowed directly into the divisions 504 from the inlet line 502. However, because the multiphase fluid is split among the divisions 504, the velocity of the multiphase fluid is reduced. In some embodiments, the reduction in velocity of the multiphase fluid dissipates any slugs within the multiphase fluid. 30 [0050] The distribution header 506 may also be in the same plane as the inlet line 502. Thus, the multiphase fluid may be flowed directly into the distribution header 506 from the -9- WO 2014/018148 PCT/US2013/039089 divisions 504. Within the distribution header 506, the multiphase fluid may be split among the upper fingers 508 and the lower fingers 510. This may further reduce the velocity of the multiphase fluid. [0051] In some embodiments, the distribution header 506 is a stratification section that is 5 configured to perform an initial bulk separation of gases and liquids within the multiphase fluid. Thus, gases may be flowed into the upper fingers 508, and liquids may be flowed into the lower fingers 510. The gases may be flowed from the upper fingers 508 to corresponding upper pipes 512, and the liquids may be flowed from the lower fingers 510 to corresponding lower pipes 514. In some embodiments, the upper pipes 512 are parallel to the lower pipes 10 514. [0052] Fig. 7 is a perspective view of another multiphase separation system 700. The multiphase separation system 700 may include an inlet line 702 configured to allow a multiphase fluid to flow into the multiphase separation system 700. The inlet line 702 may include a number of divisions 704 configured to lower a velocity of the multiphase fluid and 15 feed the multiphase fluid into a distribution header 706. [0053] The distribution header 706 is configured to split the multiphase fluid among a number of pipes 708 in a same plane as the distribution header. Each pipe 708 may include an expansion zone 710 configured to lower the velocity and the pressure of the multiphase fluid. The multiphase fluid is split between each upper finger 712 and a corresponding lower 20 pipe 714. [0054] Each upper finger 712 may feed into a corresponding upper pipe 716 in a second plane disposed above and substantially parallel to the plane of the distribution header 706. Each lower pipe 714 may be in the same plane as the distribution header 706. In addition, each upper pipe 716 may be coupled to a corresponding lower pipe 714 via a downcomer 25 720. The downcomer 720 may be configured at a right angle (as shown) or an oblique angle. [0055] Each lower pipe 714 can be configured to allow entrained gases within liquids to rise to the corresponding upper pipe 716 via the downcomer 720. Each upper pipe 716 may feed into a common gas header 722. The gas header 722 may be configured to lower a velocity of gases to allow entrained liquid droplets to coalesce and drop to any of the lower 30 pipes 714 via any of the downcomers 720. -10- WO 2014/018148 PCT/US2013/039089 [0056] The multiphase separation system 700 may include a liquid header 724 for collecting the liquids from the lower pipes 714 and flowing the liquids out of the multiphase separation system 700 via liquid outlet lines 726. In addition, the gas header 722 may include gas outlet lines 728 for flowing the gases out of the multiphase separation system 700. 5 [0057] The schematic of Fig. 7 is not intended to indicate that the subsea multiphase separation system 700 is to include all of the components shown in Fig. 7. Further, any number of additional components may be included within the subsea multiphase separation system 700, depending on the details of the specific implementation. For example, the lower pipe 714 may be extended, with or without an optional sealing downcomer, to increase 10 residence time in the liquid phase and achieve oil/water separation. This may allow for the enhancement or the elimination of downstream oil/water separation steps and equipment. Separate oil and water outlets can be included in the liquid header 724 for flowing the oil and water out of the multiphase separation system 700. [0058] Fig. 8 is a side view of the multiphase separation system 700 of Fig. 7. As shown 15 in Fig. 8, the divisions 704 may be in the same plane as the inlet line 702. Thus, the multiphase fluid may be flowed directly into the divisions 704 from the inlet line 702. However, because the multiphase fluid is split among the divisions 704, the velocity of the multiphase fluid is reduced. In some embodiments, such a reduction in velocity of the multiphase fluid dissipates any slugs within the multiphase fluid. 20 [00591 The distribution header 706 may also be in the same plane as the inlet line 702. Thus, the multiphase fluid may be flowed directly into the distribution header 706 from the divisions 704. Within the distribution header 706, the multiphase fluid may be split among the pipes 708. Within the pipes 708, the multiphase fluid may be flowed through the expansion zone 710, resulting in a reduction of the pressure and velocity of the multiphase 25 fluid. [0060] The multiphase fluid may then be split between each of the upper fingers 712 and the corresponding lower pipe 714. This may further reduce the velocity of the multiphase fluid. In some embodiments, the distribution header 706 acts as a stratification section that is configured to perform an initial bulk separation of gases and liquids within the multiphase 30 fluid. Thus, gases may be flowed into the upper fingers 712, and liquids may remain in the lower pipes 714. In addition, the gases may be flowed from the upper fingers 712 to -11corresponding upper pipes 716. In some embodiments, the upper pipes 716 are parallel to the lower pipes 714. While the present techniques may be susceptible to various modifications and alternative forms, the embodiments discussed above have been shown only by way of example. 5 However, it should again be understood that the techniques is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. 10 12
Claims (26)
1. A multiphase separation system, including: an inlet line configured to feed a multiphase fluid into a circular distribution header within the multiphase separation system, wherein the circular distribution header 5 is coupled to a number of upper lines and a number of lower lines; each upper line configured to feed gases into a circular gas header, wherein the circular gas header is in a second plane that is above a plane of the circular distribution header; each lower line configured to feed liquids into a circular liquid header, wherein the 10 circular liquid header is in a third plane that is below the plane of the circular distribution header; a gas outlet line that is coupled to the circular gas header and is configured to flow the gases out of the multiphase separation system; and a liquid outlet line that is coupled to the circular liquid header and is configured to 15 flow the liquids out of the multiphase separation system; wherein the gas outlet line and the liquid outlet line are coupled via a downcomer configured to allow entrained liquids to flow from the gas outlet line to the liquid outlet line.
2. The multiphase separation system of claim 1, wherein the number of upper 20 lines and the number of lower lines are perpendicular to the circular distribution header.
3. The multiphase separation system of any of claims 1 or 2, wherein the circular gas header includes a droplet separation section configured to remove entrained liquids from the gases. 25
4. The multiphase separation system of any one of claims 1-3, wherein the circular liquid header includes a liquid degassing section configured to remove entrained gases from the liquids.
5. The multiphase separation system of any one of claims 1-4, wherein the multiphase separation system is implemented within a subsea environment. 14
6. The multiphase separation system of any one of claims 1-5, wherein the circular distribution header includes a stratification section configured to separate gases from liquids within the multiphase fluid.
7. The multiphase separation system of any one of claims 1-6, wherein the 5 multiphase separation system includes a slug catcher.
8. The multiphase separation system of any one of claims 1-7, wherein the second plane and the third plane are parallel to the plane of the distribution header.
9. The multiphase separation system of any one of claims 1-8, wherein the 10 downcomer is configured to allow entrained gases to flow from the liquid outlet line to the gas outlet line.
10. The multiphase separation system of any one of claims 1-9, wherein the multiphase fluid includes production fluids from a subsea well.
11. The multiphase separation system of any one of claims 1-10, wherein a 15 desander is located upstream of the inlet line.
12. The multiphase separation system of any one of claims 1-11, wherein a desander is located downstream of the liquid outlet line.
13. The multiphase separation system of any one of claims 1-12, including; an oil/water separation section that is coupled to the circular liquid header and is 20 configured to separate the liquids into oil and water; an oil outlet line that is coupled to the oil/water separation section and is configured to flow the oil out of the multiphase separation system; and a water outlet line that is coupled to the oil/water separation section and is configured to flow the water out of the multiphase separation system. 15
14. The multiphase separation system of claim 13, wherein the oil/water separation section is coupled to the circular distribution header via a sealing downcomer.
15. A method for separation of liquids and gases within a multiphase fluid, 5 including: flowing a multiphase fluid into a circular distribution header of a multiphase separation system; separating the multiphase fluid into gases and liquids within the circular distribution header; 10 flowing the gases into a circular gas header that is above a plane of the circular distribution header; flowing the liquids into a circular liquid header that is below the plane of the circular distribution header; flowing the gases out of the multiphase separation system via a gas outlet line; 15 and flowing the liquids out of the multiphase separation system via a liquid outlet line; wherein entrained liquids within the gas outlet line are flowed to the liquid outlet line via a downcomer.
16. The method of claim 15, including flowing the gases into the circular gas 20 header via a number of upper lines that are perpendicular to the circular distribution header.
17. The method of claim 16, including lowering a velocity and a pressure of the gases by splitting the gases among the number of upper lines.
18. The method of any of claims 15 or 16, including flowing the liquids into the 25 circular liquid header via a number of lower lines that are perpendicular to the circular distribution header.
19. The method of claim 18, including lowering a velocity and a pressure of the liquids by splitting the liquids among the number of lower lines. 16
20. The method of any one of claims 15, 16, or 18, including flowing entrained gases within the liquid outlet line to the gas outlet line via the downcomer.
21. The method of any one of claims 15, 16, 18, or 20, wherein the multiphase separation system is implemented within a subsea environment. 5
22. The method of any one of claims 15, 16, 18, 20, or 21 , wherein the multiphase separation system is a slug catcher.
23. The method of any one of claims 15, 16, 18, or 20 - 22, including separating the multiphase fluid into the gases and the liquids within a stratification section of the circular distribution header. 10
24. The method of any one of claims 15, 16, 18, or 20 - 23, including: flowing the gases from the multiphase separation system to downstream liquid processing equipment or a gas export line; and flowing the liquids from the multiphase separation system to downstream gas processing equipment or a liquid export line. 15
25. The method of any of claims 15, 16, 18, or 20 - 24, wherein the liquids include residual solid particulates.
26. The method of any of claims 15, 16, 18, or 20 - 25, including: separating the liquids into oil and water; flowing the oil out of the multiphase separation system via an oil outlet line; and 20 flowing the water out of the multiphase separation system via a water outlet line. EXXONMOBIL UPSTREAM RESEARCH COMPANY WATERMARK PATENT AND TRADE MARKS ATTORNEYS P39879AU00
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US201261676753P | 2012-07-27 | 2012-07-27 | |
| US61/676,753 | 2012-07-27 | ||
| PCT/US2013/039089 WO2014018148A1 (en) | 2012-07-27 | 2013-05-01 | Multiphase separation system |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| AU2013293508A1 AU2013293508A1 (en) | 2015-02-19 |
| AU2013293508B2 true AU2013293508B2 (en) | 2016-04-14 |
Family
ID=49997712
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| AU2013293508A Active AU2013293508B2 (en) | 2012-07-27 | 2013-05-01 | Multiphase separation system |
Country Status (10)
| Country | Link |
|---|---|
| US (1) | US20150151219A1 (en) |
| EP (1) | EP2877264B1 (en) |
| KR (1) | KR101950672B1 (en) |
| AU (1) | AU2013293508B2 (en) |
| BR (1) | BR112015001799B1 (en) |
| CA (1) | CA2878173C (en) |
| DK (1) | DK179810B1 (en) |
| MY (1) | MY167926A (en) |
| SG (1) | SG11201408235TA (en) |
| WO (1) | WO2014018148A1 (en) |
Families Citing this family (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN101929672B (en) * | 2009-06-24 | 2012-10-24 | 中国科学院工程热物理研究所 | U-shaped water-cooling material returner |
| BR112014012285B1 (en) | 2012-01-03 | 2019-08-27 | Exxonmobil Upstream Res Co | method for producing hydrocarbons using caves |
| RU2627871C1 (en) * | 2014-03-12 | 2017-08-14 | Эксонмобил Апстрим Рисерч Компани | Underwater system (versions) and method for multiphase media separation |
| AU2015253679B8 (en) | 2014-04-29 | 2017-10-19 | Exxonmobil Upstream Research Company | Multiphase separation system |
| SG11201702668RA (en) | 2014-11-17 | 2017-06-29 | Exxonmobil Upstream Res Co | Liquid collection system |
| NO20161578A1 (en) * | 2016-09-30 | 2017-12-11 | Seabed Separation As | Method and system for separating oil well substances |
| NO346216B1 (en) * | 2019-10-15 | 2022-04-25 | Seabed Separation As | Method and system for separating oil well substances |
Citations (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4187088A (en) * | 1979-01-18 | 1980-02-05 | Maloney-Crawford Corporation | Down flow centrifugal separator |
| US20100180769A1 (en) * | 2007-03-20 | 2010-07-22 | Fmc Kongsberg Subsea As | Subsea installation and method for separation of liquid and gas |
Family Cites Families (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3768726A (en) * | 1970-05-06 | 1973-10-30 | Autometrics Co | Method and apparatus for the removal of entrained gases from mineral slurries, pulps, liquids, and the like |
| US7051540B2 (en) * | 2003-01-27 | 2006-05-30 | Battelle Memorial Institute | Methods for fluid separations, and devices capable of separating fluids |
| BRPI0518284A2 (en) * | 2004-11-24 | 2008-11-11 | Shell Int Research | apparatus for substantially separating a two-phase flow into a gaseous component and a liquid component, for substantially separating a mixture flow into a liquid component and at least one other liquid component and a gaseous component, and for substantially separating a mixture flow into component parts. based on the densities of component parts, a system for substantially separating a mixture flow into component parts, and methods for substantially separating a buffer flow and for designing a separator for substantially separating a buffer flow. |
| FR2921844B1 (en) * | 2007-10-09 | 2011-11-25 | Saipem Sa | HORIZONTAL LIQUID / GAS SEPARATION DEVICE AND SEPARATION METHOD, IN PARTICULAR LIQUID AND GAS PHASES OF A GROSS OIL |
| NO332062B1 (en) * | 2008-02-28 | 2012-06-11 | Statoilhydro Asa | Assembly for separating a multiphase stream |
| MY155337A (en) * | 2008-06-30 | 2015-10-05 | Amt Int Inc | Wet-gas separator |
| RU2451251C1 (en) * | 2011-03-22 | 2012-05-20 | Закрытое акционерное общество Финансовая компания "Центр Космос-Нефть-Газ" | Gas processing facility of gas field of oil and gas condensate deposit |
-
2013
- 2013-05-01 SG SG11201408235TA patent/SG11201408235TA/en unknown
- 2013-05-01 KR KR1020157005016A patent/KR101950672B1/en active IP Right Grant
- 2013-05-01 MY MYPI2014003548A patent/MY167926A/en unknown
- 2013-05-01 BR BR112015001799-1A patent/BR112015001799B1/en active IP Right Grant
- 2013-05-01 US US14/406,119 patent/US20150151219A1/en not_active Abandoned
- 2013-05-01 CA CA2878173A patent/CA2878173C/en not_active Expired - Fee Related
- 2013-05-01 AU AU2013293508A patent/AU2013293508B2/en active Active
- 2013-05-01 DK DKPA201500052A patent/DK179810B1/en not_active IP Right Cessation
- 2013-05-01 EP EP13823576.7A patent/EP2877264B1/en active Active
- 2013-05-01 WO PCT/US2013/039089 patent/WO2014018148A1/en active Application Filing
Patent Citations (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4187088A (en) * | 1979-01-18 | 1980-02-05 | Maloney-Crawford Corporation | Down flow centrifugal separator |
| US20100180769A1 (en) * | 2007-03-20 | 2010-07-22 | Fmc Kongsberg Subsea As | Subsea installation and method for separation of liquid and gas |
Also Published As
| Publication number | Publication date |
|---|---|
| BR112015001799B1 (en) | 2021-06-22 |
| EP2877264B1 (en) | 2019-09-11 |
| US20150151219A1 (en) | 2015-06-04 |
| KR101950672B1 (en) | 2019-02-21 |
| KR20150038398A (en) | 2015-04-08 |
| SG11201408235TA (en) | 2015-01-29 |
| EP2877264A4 (en) | 2016-04-27 |
| DK179810B1 (en) | 2019-07-01 |
| MY167926A (en) | 2018-10-03 |
| DK201500052A1 (en) | 2015-03-09 |
| EP2877264A1 (en) | 2015-06-03 |
| CA2878173A1 (en) | 2014-01-30 |
| CA2878173C (en) | 2018-09-25 |
| AU2013293508A1 (en) | 2015-02-19 |
| WO2014018148A1 (en) | 2014-01-30 |
| BR112015001799A2 (en) | 2017-07-04 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| AU2013330449B2 (en) | Multiphase separation system | |
| AU2013293508B2 (en) | Multiphase separation system | |
| DK179274B1 (en) | Split flow pipe separator | |
| US9371724B2 (en) | Multiphase separation system | |
| AU2013240515B2 (en) | System and method to treat a multiphase stream | |
| US20140209465A1 (en) | Separating Oil and Water Streams | |
| US20150306520A1 (en) | Multiphase Separation System | |
| CA3008916A1 (en) | Separation of water and oil from a production stream |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| FGA | Letters patent sealed or granted (standard patent) |